Drill bit

ABSTRACT

A drill bit for drilling a well bore using solid material impactors comprising a nozzle and a cavity for accelerating the velocity of the solid material impactors and directing flow of the solid material impactors through the nozzle. The drill bit may also comprise a junk slot for return flow of the drilling fluid and solid material impactors.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of 35 U.S.C. 111(b)provisional application Ser. No. 60/463,903 filed Apr. 16, 2003 andentitled Drill Bit.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND

There are many variables to consider to ensure a usable well bore isconstructed when using cutting systems and processes for the drilling ofwell bores or the cutting of formations for the construction of tunnelsand other subterranean earthen excavations. Many variables, such asformation hardness, abrasiveness, pore pressures, and formation elasticproperties affect the effectiveness of a particular drill bit indrilling a well bore. Additionally, in drilling well bores, formationhardness and a corresponding degree of drilling difficulty may increaseexponentially as a function of increasing depth. The rate at which adrill bit may penetrate the formation typically decreases with harderand tougher formation materials and formation depth.

When the formation is relatively soft, as with shale, material removedby the drill bit will have a tendency to reconstitute onto the teeth ofthe drill bit. Build-up of the reconstituted formation on the drill bitis typically referred to as “bit balling” and reduces the depth that theteeth of the drill bit will penetrate the bottom surface of the wellbore, thereby reducing the efficiency of the drill bit. Particles of ashale formation also tend to reconstitute back onto the bottom surfaceof the bore hole. The reconstitution of a formation back onto the bottomsurface of the bore hole is typically referred to as “bottom balling”.Bottom balling prevents the teeth of a drill bit from engaging virginformation and spreads the impact of a tooth over a wider area, therebyalso reducing the efficiency of a drill bit. Additionally, higherdensity drilling muds that are required to maintain well bore stabilityor well bore pressure control exacerbate bit balling and the bottomballing problems.

When the drill bit engages a formation of a harder rock, the teeth ofthe drill bit press against the formation and densify a small area underthe teeth to cause a crack in the formation. When the porosity of theformation is collapsed, or densified, in a hard rock formation below atooth, conventional drill bit nozzles ejecting drilling fluid are usedto remove the crushed material from below the drill bit. As a result, acushion, or densification pad, of densified material is left on thebottom surface by the prior art drill bits. If the densification pad isleft on the bottom surface, force by a tooth of the drill bit will bedistributed over a larger area and reduce the effectiveness of a drillbit.

There are generally two main categories of modern drill bits that haveevolved over time. These are the commonly known fixed cutter drill bitand the roller cone drill bit. Additional categories of drilling includepercussion drilling and mud hammers. However, these methods are not aswidely used as the fixed cutter and roller cone drill bits. Within thesetwo primary categories (fixed cutter and roller cone), there are a widevariety of variations, with each variation designed to drill a formationhaving a general range of formation properties.

The fixed cutter drill bit and the roller cone type drill bit generallyconstitute the bulk of the drill bits employed to drill oil and gaswells around the world. When a typical roller cone rock bit toothpresses upon a very hard, dense, deep formation, the tooth point mayonly penetrate into the rock a very small distance, while also at leastpartially, plastically “working” the rock surface. Under conventionaldrilling techniques, such working the rock surface may result in thedensification as noted above in hard rock formations.

With roller cone type drilling bits, a relationship exists between thenumber of teeth that impact upon the formation and the drilling RPM ofthe drill bit. A description of this relationship and an approach toimproved drilling technology is set forth and described in U.S. Pat. No.6,386,300 issued May 14, 2002, incorporated herein by reference for allpurposes. The '300 patent discloses the use of solid material impactorsintroduced into drilling fluid and pumped though a drill string anddrill bit to contact the rock formation ahead of the drill bit. Thekinetic energy of the impactors leaving the drill bit is given by thefollowing equation: E_(k)=½ Mass(Velocity)². The mass and/or velocity ofthe impactors may be chosen to satisfy the mass-velocity relationship inorder to structurally alter the rock formation.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, reference ismade to the following description taken in conjunction with theaccompanying drawings in which:

FIG. 1 is a side elevational view of a drilling system utilizing a firstembodiment of a drill bit;

FIG. 2 is a top plan view of the bottom surface of a well bore formed bythe drill bit of FIG. 1;

FIG. 3 is an end elevational view of the drill bit of FIG. 1;

FIG. 4 is an enlarged end elevational view of the drill bit of FIG. 3;

FIG. 5 is a perspective view of the drill bit of FIG. 1;

FIG. 6 is a perspective view of the drill bit of FIG. 1 illustrating abreaker and junk slot of a drill bit;

FIG. 7 is a side elevational view of the drill bit of FIG. 1illustrating a flow of solid material impactors;

FIG. 8 is a top elevational view of the drill bit of FIG. 1 illustratingside and center cavities;

FIG. 9 is a canted top elevational view of the drill bit of FIG. 8;

FIG. 10 is a cutaway view of the drill bit of FIG. 1 engaged in a wellbore;

FIG. 11 is a schematic diagram of the orientation of the nozzles of asecond embodiment of a drill bit;

FIG. 12 is a side cross-sectional view of the rock formation created bythe drill bit of FIG. 1 represented by the schematic of the drill bit ofFIG. 1 inserted therein;

FIG. 13 is a side cross-sectional view of the rock formation created bydrill bit of FIG. 1 represented by the schematic of the drill bit ofFIG. 1 inserted therein;

FIG. 14 is a perspective view of an alternate embodiment of a drill bit;

FIG. 15 is a perspective view of the drill bit of FIG. 14; and

FIG. 16 illustrates an end elevational view of the drill bit of FIG. 14.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In the drawings and description that follows, like parts are markedthroughout the specification and drawings with the same referencenumerals, respectively. The drawing figures are not necessarily toscale. Certain features of the invention may be shown exaggerated inscale or in somewhat schematic form and some details of conventionalelements may not be shown in the interest of clarity and conciseness.The present invention is susceptible to embodiments of different forms.Specific embodiments are described in detail and are shown in thedrawings, with the understanding that the present disclosure is to beconsidered an exemplification of the principles of the invention, and isnot intended to limit the invention to that illustrated and describedherein. It is to be fully recognized that the different teachings of theembodiments discussed below may be employed separately or in anysuitable combination to produce desired results. The variouscharacteristics mentioned above, as well as other features andcharacteristics described in more detail below, will be readily apparentto those skilled in the art upon reading the following detaileddescription of the embodiments, and by referring to the accompanyingdrawings.

FIG. 1 shows a first embodiment of a drill bit 10 at the bottom of awell bore 20 and attached to a drill string 30. The drill bit 10 actsupon a bottom surface 22 of the well bore 20. The drill string 30 has acentral passage 32 that supplies drilling fluids 40 to the drill bit 10.The drill bit 10 uses the drilling fluids 40 and solid materialimpactors when acting upon the bottom surface 22 of the well bore 20.The solid material impactors reduce bit balling and bottom balling bycontacting the bottom surface 22 of the well bore 20 with the solidmaterial impactors. The solid material impactors may be used for anytype of contacting of the bottom surface 22 of the well bore 20, whetherit be abrasion-type drilling, impact-type drilling, or any otherdrilling using solid material impactors. The drilling fluids 40 thathave been used by the drill bit 10 on the bottom surface 22 of the wellbore 20 exit the well bore 20 through a well bore annulus 24 between thedrill string 30 and the inner wall 26 of the well bore 20. Particles ofthe bottom surface 22 removed by the drill bit 10 exit the well bore 20with the drill fluid 40 through the well bore annulus 24. The drill bit10 creates a rock ring 42 at the bottom surface 22 of the well bore 20.

Referring now to FIG. 2, a top view of the rock ring 42 formed by thedrill bit 10 is illustrated. An interior cavity 44 is worn away by aninterior portion of the drill bit 10 and the exterior cavity 46 andinner wall 26 of the well bore 20 are worn away by an exterior portionof the drill bit 10. The rock ring 42 possesses hoop strength, whichholds the rock ring 42 together and resists breakage. The hoop strengthof the rock ring 42 is typically much less than the strength of thebottom surface 22 or the inner wall 26 of the well bore 20, therebymaking the drilling of the bottom surface 22 less demanding on the drillbit 10. By applying a compressive load and a side load, shown witharrows 41, on the rock ring 42, the drill bit 10 causes the rock ring 42to fracture. The drilling fluid 40 then washes the residual pieces ofthe rock ring 42 back up to the surface through the well bore annulus24.

Remaining with FIG. 2, mechanical cutters, utilized on many of thesurfaces of the drill bit 10, may be any type of protrusion or surfaceused to abrade the rock formation by contact of the mechanical cutterswith the rock formation. The mechanical cutters may be PolycrystallineDiamond Coated (PDC), or any other suitable type mechanical cutter suchas tungsten carbide cutters. The mechanical cutters may be formed in avariety of shapes, for example, hemispherically shaped, cone shaped,etc. Several sizes of mechanical cutters are also available, dependingon the size of drill bit used and the hardness of the rock formationbeing cut.

Referring now to FIG. 3, an end elevational view of the drill bit 10 ofFIG. 1 is illustrated. The drill bit 10 comprises two side nozzles 200A,200B and a center nozzle 202. The side and center nozzles 200A, 200B,202 discharge drilling fluid and solid material impactors (not shown)into the rock formation or other surface being excavated. The solidmaterial impactors may comprise steel shot ranging in diameter fromabout 0.010 to about 0.500 of an inch. However, various diameters andmaterials such as ceramics, etc. may be utilized in combination with thedrill bit 10. The solid material impactors contact the bottom surface 22of the well bore 20 and are circulated through the annulus 24 to thesurface. The solid material impactors may also make up any suitablepercentage of the drill fluid for drilling through a particularformation.

Still referring to FIG. 3, the center nozzle 202 is located in a centerportion 203 of the drill bit 10. The center nozzle 202 may be angled tothe longitudinal axis of the drill bit 10 to create an interior cavity44 and also cause the rebounding solid material impactors to flow intothe major junk slot 204A. The side nozzle 200A located on a side arm214A of the drill bit 10 may also be oriented to allow the solidmaterial impactors to contact the bottom surface 22 of the well bore 20and then rebound into the major junk slot 204A. The second side nozzle200B is located on a second side arm 214B. The second side nozzle 200Bmay be oriented to allow the solid material impactors to contact thebottom surface 22 of the well bore 20 and then rebound into a minor junkslot 204B. The orientation of the side nozzles 200A, 200B may be used tofacilitate the drilling of the large exterior cavity 46. The sidenozzles 200A, 200B may be oriented to cut different portions of thebottom surface 22. For example, the side nozzle 200B may be angled tocut the outer portion of the exterior cavity 46 and the side nozzle 200Amay be angled to cut the inner portion of the exterior cavity 46. Themajor and minor junk slots 204A, 204B allow the solid materialimpactors, cuttings, and drilling fluid 40 to flow up through the wellbore annulus 24 back to the surface. The major and minor junk slots204A, 204B are oriented to allow the solid material impactors andcuttings to freely flow from the bottom surface 22 to the annulus 24.

As described earlier, the drill bit 10 may also comprise mechanicalcutters and gauge cutters. Various mechanical cutters are shown alongthe surface of the drill bit 10. Hemispherical PDC cutters areinterspersed along the bottom face and the side walls 210 of the drillbit 10. These hemispherical cutters along the bottom face break down thelarge portions of the rock ring 42 and also abrade the bottom surface 22of the well bore 20. Another type of mechanical cutter along the sidearms 214A, 214B are gauge cutters 230. The gauge cutters 230 form thefinal diameter of the well bore 20. The gauge cutters 230 trim a smallportion of the well bore 20 not removed by other means. Gauge bearingsurfaces 206 are interspersed throughout the side walls 210 of the drillbit 10. The gauge bearing surfaces 206 ride in the well bore 20 alreadytrimmed by the gauge cutters 230. The gauge bearing surfaces 206 mayalso stabilize the drill bit 10 within the well bore 20 and aid inpreventing vibration.

Still referring to FIG. 3, the center portion 203 comprises a breakersurface, located near the center nozzle 202, comprising mechanicalcutters 208 for loading the rock ring 42. The mechanical cutters 208abrade and deliver load to the lower stress rock ring 42. The mechanicalcutters 208 may comprise PDC cutters, or any other suitable mechanicalcutters. The breaker surface is a conical surface that creates thecompressive and side loads for fracturing the rock ring 42. The breakersurface and the mechanical cutters 208 apply force against the innerboundary of the rock ring 42 and fracture the rock ring 42. Oncefractured, the pieces of the rock ring 42 are circulated to the surfacethrough the major and minor junk slots 204A, 204B.

Referring now to FIG. 4, an enlarged end elevational view of the drillbit 10 is shown. As shown more clearly in FIG. 4, the gauge bearingsurfaces 206 and mechanical cutters 208 are interspersed on the outerside walls 210 of the drill bit 10. The mechanical cutters 208 along theside walls 210 may also aid in the process of creating drill bit 10stability and also may perform the function of the gauge bearingsurfaces 206 if they fail. The mechanical cutters 208 are oriented invarious directions to reduce the wear of the gauge bearing surface 206and also maintain the correct well bore 20 diameter. As noted with themechanical cutters 208 of the breaker surface, the solid materialimpactors fracture the bottom surface 22 of the well bore 20 and, assuch, the mechanical cutters 208 remove remaining ridges of rock andassist in the cutting of the bottom hole. However, the drill bit 10 neednot necessarily comprise the mechanical cutters 208 on the side wall 210of the drill bit 10.

Referring now to FIG. 5, a side elevational view of the drill bit 10 isillustrated. FIG. 5 shows the gauge cutters 230 included along the sidearms 214A, 214B of the drill bit 10. The gauge cutters 230 are orientedso that a cutting face of the gauge cutter 230 contacts the inner wall26 of the well bore 20. The gauge cutters 230 may contact the inner wall26 of the well bore at any suitable backrake, for example a backrake of15° to 45°. Typically, the outer edge of the cutting face scrapes alongthe inner wall 26 to refine the diameter of the well bore 20.

Still referring to FIG. 5, one side nozzle 200A is disposed on aninterior portion of the side arm 214A and the second side nozzle 200B isdisposed on an exterior portion of the opposite side arm 214B. Althoughthe side nozzles 200A, 200B are shown located on separate side arms214A, 214B of the drill bit 10, the side nozzles 200A, 200B may also bedisposed on the same side arm 214A or 214B. Also, there may only be oneside nozzle, 200A or 200B. Also, there may only be one side arm, 214A or214B.

Each side arm 214A, 214B fits in the exterior cavity 46 formed by theside nozzles 200A, 200B and the mechanical cutters 208 on the face 212of each side arm 214A, 214B. The solid material impactors from one sidenozzle 200A rebound from the rock formation and combine with thedrilling fluid and cuttings flow to the major junk slot 204A and up tothe annulus 24. The flow of the solid material impactors, shown byarrows 205, from the center nozzle 202 also rebound from the rockformation up through the major junk slot 204A.

Referring now to FIGS. 6 and 7, the minor junk slot 204B, breakersurface, and the second side nozzle 200B are shown in greater detail.The breaker surface is conically shaped, tapering to the center nozzle202. The second side nozzle 200B is oriented at an angle to allow theouter portion of the exterior cavity 46 to be contacted with solidmaterial impactors. The solid material impactors then rebound up throughthe minor junk slot 204B, shown by arrows 205, along with any cuttingsand drilling fluid 40 associated therewith.

Referring now to FIGS. 8 and 9, top elevational views of the drill bit10 are shown. Each nozzle 200A, 200B, 202 receives drilling fluid 40 andsolid material impactors from a common plenum feeding separate cavities250, 251, and 252. The center cavity 250 feeds drilling fluid 40 andsolid material impactors to the center nozzle 202 for contact with therock formation. The side cavities 251, 252 are formed in the interior ofthe side arms 214A, 214B of the drill bit 10, respectively. The sidecavities 251, 252 provide drilling fluid 40 and solid material impactorsto the side nozzles 200A, 200B for contact with the rock formation. Byutilizing separate cavities 250, 251,252 for each nozzle 202, 200A,200B, the percentages of solid material impactors in the drilling fluid40 and the hydraulic pressure delivered through the nozzles 200A, 200B,202 can be specifically tailored for each nozzle 200A, 200B, 202. Solidmaterial impactor distribution can also be adjusted by changing thenozzle diameters of the side and center nozzles 200A, 200B, and 202.However, in alternate embodiments, other arrangements of the cavities250, 251, 252, or the utilization of a single cavity, are possible.

Referring now to FIG. 10, the drill bit 10 in engagement with the rockformation 270 is shown. As previously discussed, the solid materialimpactors 272 flow from the nozzles 200A, 200B, 202 and make contactwith the rock formation 270 to create the rock ring 42 between the sidearms 214A, 214B of the drill bit 10 and the center nozzle 202 of thedrill bit 10. The solid material impactors 272 from the center nozzle202 create the interior cavity 44 while the side nozzles 200A, 200Bcreate the exterior cavity 46 to form the outer boundary of the rockring 42. The gauge cutters 230 refine the more crude well bore 20 cut bythe solid material impactors 272 into a well bore 20 with a more smoothinner wall 26 of the correct diameter.

Still referring to FIG. 10, the solid material impactors 272 flow fromthe first side nozzle 200A between the outer surface of the rock ring 42and the interior wall 216 in order to move up through the major junkslot 204A to the surface. The second side nozzle 200B (not shown) emitssolid material impactors 272 that rebound toward the outer surface ofthe rock ring 42 and to the minor junk slot 204B (not shown). The solidmaterial impactors 272 from the side nozzles 200A, 200B may contact theouter surface of the rock ring 42 causing abrasion to further weaken thestability of the rock ring 42. Recesses 274 around the breaker surfaceof the drill bit 10 may provide a void to allow the broken portions ofthe rock ring 42 to flow from the bottom surface 22 of the well bore 20to the major or minor junk slot 204A, 204B.

Referring now to FIG. 11, an example orientation of the nozzles 200A,200B, 202 are illustrated. The center nozzle 202 is disposed left of thecenter line of the drill bit 10 and angled on the order of around 20°left of vertical. Alternatively, both of the side nozzles 200A, 200B maybe disposed on the same side arm 214 of the drill bit 10 as shown inFIG. 11. In this embodiment, the first side nozzle 200A, oriented to cutthe inner portion of the exterior cavity 46, is angled on the order ofaround 10° left of vertical. The second side nozzle 200B is oriented atan angle on the order of around 14° right of vertical. This particularorientation of the nozzles allows for a large interior cavity 44 to becreated by the center nozzle 202. The side nozzles 200A, 200B create alarge enough exterior cavity 46 in order to allow the side arms 214A,214B to fit in the exterior cavity 46 without incurring a substantialamount of resistance from uncut portions of the rock formation 270. Byvarying the orientation of the center nozzle 202, the interior cavity 44may be substantially larger or smaller than the interior cavity 44illustrated in FIG. 10. The side nozzles 200A, 200B may be varied inorientation in order to create a larger exterior cavity 46, therebydecreasing the size of the rock ring 42 and increasing the amount ofmechanical cutting required to drill through the bottom surface 22 ofthe well bore 20. Alternatively, the side nozzles 200A, 200B may beoriented to decrease the amount of the inner wall 26 contacted by thesolid material impactors 272. By orienting the side nozzles 200A, 200Bat, for example, a vertical orientation, only a center portion of theexterior cavity 46 would be cut by the solid material impactors and themechanical cutters would then be required to cut a large portion of theinner wall 26 of the well bore 20.

Referring now to FIGS. 12 and 13, side cross-sectional views of thebottom surface 22 of the well bore 20 drilled by the drill bit 10 areshown. With the center nozzle angled on the order of around 20° left ofvertical and the side nozzles 200A, 200B angled on the order of around10° left of vertical and around 14° right of vertical, respectively, therock ring 42 is formed. By increasing the angle of the side nozzle 200A,200B orientation, an alternate rock ring 42 shape and bottom surface 22is cut as shown in FIG. 13. The interior cavity 44 and rock ring 42 aremuch more shallow as compared with the rock ring 42 in FIG. 12. Bydiffering the shape of the bottom surface 22 and rock ring 42, morestress is placed on the gauge bearing surfaces 206, mechanical cutters208, and gauge cutters 230.

Although the drill bit 10 is described comprising orientations ofnozzles and mechanical cutters, any orientation of either nozzles,mechanical cutters, or both may be utilized. The drill bit 10 need notcomprise a center portion 203. The drill bit 10 also need not evencreate the rock ring 42. For example, the drill bit may only comprise asingle nozzle and a single junk slot. Furthermore, although thedescription of the drill bit 10 describes types and orientations ofmechanical cutters, the mechanical cutters may be formed of a variety ofsubstances, and formed in a variety of shapes.

Referring now to FIGS. 14-16, a drill bit 110 in accordance with asecond embodiment is illustrated. As previously noted, the mechanicalcutters, such as the gauge cutters 230, mechanical cutters 208, andgauge bearing surfaces 206 may not be necessary in conjunction with thenozzles 200A, 200B, 202 in order to drill the required well bore 20. Theside wall 210 of the drill bit 110 may or may not be interspersed withmechanical cutters. The side nozzles 200A, 200B and the center nozzle202 are oriented in the same manner as in the drill bit 10, however, theface 212 of the side arms 214A, 214B comprises angled (PDCs) 280 as themechanical cutters.

Still referring to FIGS. 14-16, each row of PDCs 280 is angled to cut aspecific area of the bottom surface 22 of the well bore 20. A first rowof PDCs 280A is oriented to cut the bottom surface 22 and also cut theinner wall 26 of the well bore 20 to the proper diameter. A groove 282is disposed between the cutting faces of the PDCs 280 and the face 212of the drill bit 110. The grooves 282 receive cuttings, drilling fluid40, and solid material impactors and guide them toward the center nozzle202 to flow through the major and minor junk slots 204A, 204B toward thesurface. The grooves 282 may also guide some cuttings, drilling fluid40, and solid material impactors toward the inner wall 26 to be receivedby the annulus 24 and also flow to the surface. Each subsequent row ofPDCs 280B, 280C may be oriented in the same or different position thanthe first row of PDCs 280A. For example, the subsequent rows of PDCs280B, 280C may be oriented to cut the exterior face of the rock ring 42as opposed to the inner wall 26 of the well bore 20. The grooves 282 onone side arm 214A may also be oriented to guide the cuttings anddrilling fluid 40 toward the center nozzle 202 and to the annulus 24 viathe major junk slot 204A. The second side arm 214B may have grooves 282oriented to guide the cuttings and drilling fluid 40 to the inner wall26 of the well bore 20 and to the annulus 24 via the minor junk slot204B.

With the drill bit 110, gauge cutters are not required. The PDCs 280located on the face 212 of each side arm 214A, 214B are sufficient tocut the inner wall 26 to the correct size. However, mechanical cuttersmay be placed throughout the side wall 210 of the drill bit 10 tofurther enhance the stabilization and cutting ability of the drill bit10.

While specific embodiments have been shown and described, modificationscan be made by one skilled in the art without departing from the spiritor teaching of this invention. The embodiments as described areexemplary only and are not limiting. Many variations and modificationsare possible and are within the scope of the invention. Accordingly, thescope of protection is not limited to the embodiments described, but isonly limited by the claims that follow, the scope of which shall includeall equivalents of the subject matter of the claims.

1. A drill bit for drilling a well bore using solid material impactors,said drill bit comprising: a center portion comprising a center nozzle;a side arm comprising a side arm nozzle; a center cavity foraccelerating the velocity of the solid material impactors and directingflow of the solid material impactors through said center nozzle; and aside arm cavity for accelerating the velocity of the solid materialimpactors and directing flow of the solid material impactors throughsaid side arm nozzle.
 2. The drill bit of claim 1 further comprising ajunk slot for receiving flow of the solid material impactors afterleaving said drill bit.
 3. The drill bit of claim 2 further comprising asecond junk slot for receiving flow of the solid material impactorsafter leaving said drill bit.
 4. The drill bit of claim 1 furthercomprising mechanical cutters on the exterior surface of said side armand said center portion.
 5. The drill bit of claim 1 further comprisinga mechanical cutter on the side wall of said drill bit.
 6. The drill bitof claim 1 further comprising a gauge cutter.
 7. The drill bit of claim1 wherein said central portion comprises a breaker surface.
 8. The drillbit of claim 7 wherein said breaker surface is conical in shape.
 9. Thedrill bit of claim 7 wherein said breaker surface comprises a mechanicalcutter.
 10. The drill bit of claim 1 wherein said center nozzle and saidside nozzle are oriented at angles to the longitudinal axis of saiddrill bit.
 11. The drill bit of claim 1 wherein said center nozzle isoffset from the longitudinal axis of said drill bit.
 12. The drill bitof claim 1 wherein said side arm comprises a mechanical cutter and agroove for guiding the flow of the solid material impactors afterleaving said drill bit.
 13. The drill bit of claim 1 further comprisingmore than one side arm and more than one side nozzle.
 14. The drill bitof claim 1 further comprising more than one center nozzle.
 15. A methodof drilling a well bore through a formation comprising: flowing solidmaterial impactors into a drill bit; accelerating said solid materialimpactors as said solid material impactors flow through said drill bit;and contacting the formation with said accelerated solid materialimpactors after flowing through said drill bit.
 16. The method of claim15 further comprising accelerating said solid material impactors byflowing said solid material impactors through a cavity within said drillbit and out a nozzle.
 17. The method of claim 16 further comprising:flowing solid material impactors through a center cavity in a centerportion of said drill bit and out a center nozzle; and flowing solidmaterial impactors through a side arm cavity in a side arm of said drillbit and out a side arm nozzle.
 18. The method of claim 15 furthercomprising flowing solid material impactors through a junk slot on theouter surface of said drill bit after contacting the formation.
 19. Themethod of claim 18 further comprising flowing solid material impactorsthrough a second junk slot on the outer surface of said drill bit aftercontacting the formation.
 20. The method of claim 15 further comprisingdirecting the flow of said solid material impactors from said drill bitat an angle to the longitudinal axis of said drill bit.
 21. The methodof claim 17 further comprising breaking apart the formation withmechanical cutters on said drill bit.
 22. The method of claim 21 furthercomprising breaking apart the formation with mechanical cutters on saidcentral portion, said side arm, and the side wall of said drill bit. 23.The method of claim 17 further comprising: breaking apart the formationwith mechanical cutters on said side arm; and flowing said solidmaterial impactors through grooves in said side arm after leaving saiddrill bit.
 24. A drill bit for drilling a well bore using solid materialimpactors, said drill bit comprising: a central portion comprising acenter nozzle; a side arm comprising a side nozzle and a second sidenozzle; a central cavity for accelerating the velocity of the solidmaterial impactors and directing flow of the solid material impactorsthrough said center nozzle; and a side cavity for accelerating thevelocity of the solid material impactors and directing flow of the solidmaterial impactors through said side nozzle and said second side nozzle.25. The drill bit of claim 24 further comprising a junk slot forreceiving flow of the solid material impactors after leaving said drillbit.
 26. The drill bit of claim 25 further comprising a second junk slotfor receiving flow of the solid material impactors after leaving saiddrill bit.
 27. The drill bit of claim 24 further comprising mechanicalcutters on the exterior surface of said side arm and said centerportion.
 28. The drill bit of claim 24 further comprising a mechanicalcutter on the side wall of said drill bit.
 29. The drill bit of claim 24further comprising a gauge cutter.
 30. The drill bit of claim 24 whereinsaid central portion comprises a breaker surface.
 31. The drill bit ofclaim 30 wherein said breaker surface is conical in shape.
 32. The drillbit of claim 30 wherein said breaker surface comprises a mechanicalcutter.
 33. The drill bit of claim 24 wherein said center nozzle, saidside nozzle, and said second side nozzle are oriented at angles to thelongitudinal axis of said drill bit.
 34. The drill bit of claim 24wherein said center nozzle is offset from the longitudinal axis of saiddrill bit.
 35. The drill bit of claim 24 wherein said side arm comprisesa mechanical cutter and a groove for guiding the flow of the solidmaterial impactors after leaving said drill bit.
 36. The drill bit ofclaim 24 further comprising more than one side arm and more than oneside nozzle and second side nozzle.
 37. The drill bit of claim 24further comprising more than one center nozzle.
 38. A method of drillinga well bore through a formation comprising: flowing solid materialimpactors into a drill bit; accelerating said solid material impactorsas said solid material impactors flow through said drill bit by flowingsaid solid material impactors through a center cavity within a centerportion of said drill bit and out a center nozzle and through a side armcavity in a side arm of said drill bit and out a side nozzle and asecond side nozzle; contacting the formation with said accelerated solidmaterial impactors after flowing through said drill bit.
 39. The methodof claim 38 further comprising flowing solid material impactors througha junk slot on the outer surface of said drill bit after contacting theformation.
 40. The method of claim 39 further comprising flowing solidmaterial impactors through a second junk slot on the outer surface ofsaid drill bit after contacting the formation.
 41. The method of claim38 further comprising directing the flow of said solid materialimpactors from said drill bit at an angle to the longitudinal axis ofsaid drill bit.
 42. The method of claim 38 further comprising breakingapart the formation with mechanical cutters on said drill bit.
 43. Themethod of claim 38 further comprising breaking apart the formation withmechanical cutters on said central portion, said side arm, and the sidewall of said drill bit.
 44. The method of claim 38 further comprising:breaking apart the formation with mechanical cutters on said side arm;and flowing said solid material impactors through grooves in said sidearm after leaving said drill bit.
 45. A drill bit for drilling a wellbore using solid material impactors, said drill bit comprising: acentral portion comprising a center nozzle; a side arm comprising a sidenozzle; a second side arm comprising a second side nozzle; a centralcavity for accelerating the velocity of the solid material impactors anddirecting flow of the solid material impactors through said centernozzle; a side cavity for accelerating the velocity of the solidmaterial impactors and directing flow of the solid material impactorsthrough said side nozzle; and a second side cavity for accelerating thevelocity of the solid material impactors and directing flow of the solidmaterial impactors through said second side nozzle.
 46. The drill bit ofclaim 45 further comprising a junk slot for receiving flow of the solidmaterial impactors after leaving said drill bit.
 47. The drill bit ofclaim 46 further comprising a second junk slot for receiving flow of thesolid material impactors after leaving said drill bit.
 48. The drill bitof claim 45 further comprising mechanical cutters on the exteriorsurface of said side arm and said center portion.
 49. The drill bit ofclaim 45 further comprising a mechanical cutter on the side wall of saiddrill bit.
 50. The drill bit of claim 45 further comprising a gaugecutter.
 51. The drill bit of claim 45 wherein said central portioncomprises a breaker surface.
 52. The drill bit of claim 51 wherein saidbreaker surface is conical in shape.
 53. The drill bit of claim 51wherein said breaker surface comprises a mechanical cutter.
 54. Thedrill bit of claim 45 wherein said center nozzle, said side nozzle, andsaid second side nozzle are oriented at angles to the longitudinal axisof said drill bit.
 55. The drill bit of claim 45 wherein said centernozzle is offset from the longitudinal axis of said drill bit.
 56. Thedrill bit of claim 45 wherein said side arm comprises a mechanicalcutter and a groove for guiding the flow of the solid material impactorsafter leaving said drill bit.
 57. The drill bit of claim 45 furthercomprising more than one side arm and more than one side nozzle.
 58. Thedrill bit of claim 45 further comprising more than one center nozzle.59. A method of drilling a well bore through a formation comprising:flowing solid material impactors into a drill bit; accelerating saidsolid material impactors as said solid material impactors flow throughsaid drill bit by flowing said solid material impactors through a centercavity within a center portion of said drill bit and out a centernozzle, through a side arm cavity in a side arm of said drill bit andout a side nozzle, and through a second side arm cavity in a second sidearm and out a second side nozzle; contacting the formation with saidaccelerated solid material impactors after flowing through said drillbit.
 60. The method of claim 59 further comprising flowing solidmaterial impactors through a junk slot on the outer surface of saiddrill bit after contacting the formation.
 61. The method of claim 60further comprising flowing solid material impactors through a secondjunk slot on the outer surface of said drill bit after contacting theformation.
 62. The method of claim 59 further comprising directing theflow of said solid material impactors from said drill bit at an angle tothe longitudinal axis of said drill bit.
 63. The method of claim 59further comprising breaking apart the formation with mechanical cutterson said drill bit.
 64. The method of claim 59 further comprisingbreaking apart the formation with mechanical cutters on said centralportion, said side arm, said second side arm, and the side wall of saiddrill bit.
 65. The method of claim 59 further comprising: breaking apartthe formation with mechanical cutters on said side arm and said secondside arm; and flowing said solid material impactors through grooves insaid side arm and said second side arm after leaving said drill bit. 66.A drill bit for drilling a well bore using solid material impactors,said drill bit comprising: a nozzle; a cavity for accelerating thevelocity of the solid material impactors and directing flow of the solidmaterial impactors through said nozzle; and a junk slot for receivingflow of the solid material impactors after leaving said drill bit. 67.The drill bit of claim 66 further comprising mechanical cutters on theexterior surface of said drill bit.
 68. The drill bit of claim 66further comprising a gauge cutter.
 69. The drill bit of claim 66 whereinsaid nozzle is oriented at an angle to the longitudinal axis of saiddrill bit.
 70. The drill bit of claim 66 wherein said nozzle is offsetfrom the longitudinal axis of said drill bit.
 71. The drill bit of claim66 further comprising: a second nozzle and a second cavity foraccelerating the velocity of the solid material impactors and directingflow of the solid material impactors through said second nozzle; and asecond junk slot for receiving flow of the solid material impactorsafter leaving said drill bit.
 72. The drill bit of claim 71 wherein atleast one of said nozzle and said second nozzle is oriented at an angleto the longitudinal axis of said drill bit.
 73. The drill bit of claim71 wherein at least one of said nozzle and said second nozzle is offsetfrom the longitudinal axis of said drill bit.
 74. The drill bit of claim66 further comprising: more than two nozzles and more than two secondcavities for accelerating the velocity of the solid material impactorsand directing flow of the solid material impactors through said nozzles;and more than two junk slots for receiving flow of the solid materialimpactors after leaving said drill bit.
 75. The drill bit of claim 74wherein at least one nozzle is oriented at an angle to the longitudinalaxis of said drill bit.
 76. The drill bit of claim 74 wherein at leastone nozzle is offset from the longitudinal axis of said drill bit.